SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

Form 10-Q

|  X  |      QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended     March 31, 2002    

|     |      TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to _______

Commission file number     1-8222

          Central Vermont Public Service Corporation          
(Exact name of registrant as specified in its charter)

        Incorporated in Vermont                          03-0111290        
(State or other jurisdiction of                     (I.R.S. Employer
incorporation or organization)                    Identification No.)

        77 Grove Street, Rutland, Vermont            05701        
(Address of principal executive offices)       (Zip Code)

                              802-773-2711                              
(Registrant's telephone number, including area code)

                                                                                                         
(Former name, former address and former fiscal year, if changed since last report)

      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   X     No       

      Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of April 30, 2002 there were outstanding 11,644,517 shares of Common Stock, $6 Par Value.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Form 10-Q - 2002

Table Of Contents

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statement of Income and Retained Earnings for the three   months ended March 31, 2002 and 2001	3
	Consolidated Balance Sheets as of March 31, 2002 and December 31, 2001	4
	Consolidated Statement of Cash Flows for the three months ended    March 31, 2002 and 2001	5
	Notes to Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and   Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	26
PART II	OTHER INFORMATION	27
SIGNATURES		29

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS

(Dollars in thousands, except per share amounts)

(Unaudited)

	Three Months Ended        March 31
	2002	2001
Operating Revenues	$76,475	$78,032
Operating Expenses
Operation
Purchased power	37,614	39,449
Production and transmission	6,167	6,637
Other operation	10,676	11,436
Maintenance	3,919	4,626
Depreciation	4,315	4,250
Other taxes, principally property taxes	3,282	3,101
Taxes on income	3,343	2,407
Total operating expenses	69,316	71,906
Operating Income	7,159	6,126
Other Income and Deductions
Equity in earnings of affiliates	634	662
Allowance for equity funds during construction	31	17
Other (deductions) income, net	(5)	517
(Provision) benefit for income taxes	239	(167)
Total other income and deductions, net	899	1,029
Total Operating and Other Income	8,058	7,155
Interest Expense
Interest on long-term debt	3,126	3,209
Other interest	163	58
Allowance for borrowed funds during construction	(15)	(9)
Total interest expense, net	3,274	3,258
Net Income	4,784	3,897
Retained Earnings at Beginning of Period	69,170	78,423
Retained Earnings Before Dividends	73,954	82,320
Cash Dividend Declared
Preferred Stock	403	424
Common Stock	-	-
Total Dividends Declared	403	424
Other Adjustments	91	(11)
Retained Earnings at End of Period	$73,642	$81,885
Earnings Available For Common Stock	$ 4,381	$ 3,473
Average Shares of Common Stock Outstanding - Basic	11,622,118	11,530,896
Average Shares of Common Stock Outstanding - Diluted	11,838,093	11,530,896
Earnings Per Basic and Diluted Share of Common Stock - Basic	$.38	$.30
Earnings Per Basic and Diluted Share of Common Stock - Diluted	$.37	$.30
Dividends Paid Per Share of Common Stock	$.22	$.22

The accompanying notes are an integral part of these consolidated financial statements.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

	March 31	December 31
	2002	2001
Assets
Utility Plant, at original cost	$491,222	$490,137
Less accumulated depreciation	202,047	198,087
	289,175	292,050
Construction work-in-progress	16,953	15,727
Nuclear fuel, net	894	852
Net utility plant	307,022	308,629
Investments and Other Assets
Investments in affiliates, at equity	23,844	23,823
Non-utility investments	39,199	38,514
Non-utility property, less accumulated depreciation	2,326	2,401
Total investments and other assets	65,369	64,738
Current Assets
Cash and cash equivalents	51,956	45,491
Special deposits	8	7
Accounts receivable, less allowance for uncollectible accounts             ($1,269 in 2002 and $2,071 in 2001)	20,770	21,951
Unbilled revenues	14,971	16,404
Materials and supplies, at average cost	4,163	4,167
Prepayments	2,024	3,676
Investments held for sale	11,029	11,029
Other current assets	5,685	5,408
Total current assets	110,606	108,133
Regulatory Assets	29,389	32,403
Other Deferred Charges	6,740	7,771
Total Assets	$519,126	$521,674
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized 19,000,000 shares;              issued 11,785,848 shares; outstanding 11,635,877	$70,715	$70,715
Other paid-in capital	47,354	47,634
Accumulated other comprehensive income	(776)	(623)
Deferred compensation plans - employee stock ownership plans	(1,011)	(1,097)
Treasury stock (149,971 shares, and 175,165, respectively, at cost)	(1,982)	(2,285)
Retained Earnings	73,642	69,170
Total Common Stock Equity	187,942	183,514
Preferred and preference stock	8,054	8,054
Preferred stock with sinking fund requirements	14,000	15,000
Long-term debt	159,715	159,771
Capital lease obligations	12, 663	12,897
Total capitalization	382,374	379,236
Current Liabilities
Current portion of preferred stock	1,000	1,000
Current portion of long-term debt	7,225	7,225
Accounts payable	3,888	4,796
Accounts payable - affiliates	9,561	12,092
Accrued income taxes	3,341	74
Dividends declared	403	2,978
Nuclear decommissioning costs	2,133	2,298
Other current liabilities	18,944	19,739
Total current liabilities	46,495	50,202
Deferred Credits
Deferred income taxes	37,959	38,828
Deferred investment tax credits	5,560	5,658
Nuclear decommissioning costs	11,741	12,826
Other deferred credits	34,997	34,924
Total deferred credits	90,257	92,236
Commitments and Contingencies
Total Capitalization and Liabilities	$519,126	$521,674

The accompanying notes are an integral part of these consolidated financial statements.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)

	Three Months Ended       March 31
	2002	2001
Cash Flows Provided (Used) By:
Operating Activities
Net income	$4,784	$3,897
Adjustments to reconcile net income to net cash provided by operating activities
Equity in earnings of affiliates	(634)	(662)
Dividends received from affiliates	483	659
Equity in earnings from non-utility investment	(2,567)	(1,521)
Distribution of earnings from non-utility investments	2,604	673
Depreciation	4,315	4,250
Amortization of capital leases	272	272
Deferred income taxes and investment tax credits	(890)	(1,071)
Net (deferral) and amortization of nuclear replacement            energy and maintenance costs	1,428	161
Amortization of conservation and load management costs	554	1,342
Decrease in accounts receivable and unbilled revenues	2,600	4,849
Decrease in accounts payable	(3,348)	(4,003)
Increase in accrued income taxes	3,267	2,604
Change in other working capital items	533	(1,202)
Other, net	1,514	(173)
Net cash provided by operating activities	14,915	10,075
Investing Activities
Construction and plant expenditures	(3,255)	(3,465)
Conservation and load management expenditures	(50)	(219)
Return of capital	48	47
Non-utility investments	(1,000)	(5,611)
Other investments, net	12	53
Net cash used for investing activities	(4,245)	(9,195)
Financing Activities
Sale of common stock	106	484
Long-term debt, net	(56)	5,820
Retirement of preferred stock	(1,000)	-
Common and preferred dividends paid	(2,983)	(2,956)
Reduction in capital lease obligations	(272)	(272)
Other	-	138
Net cash (used) provided by financing activities	(4,205)	3,214
Net (Decrease) Increase In Cash and Cash Equivalents	6,465	4,094
Cash and Cash Equivalents at Beginning of Year	45,491	47,986
Cash and Cash Equivalents at End of Year	$51,956	$52,080
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized)	$3,532	$3,424
Income taxes (net of refunds)	$     47	$   953
Non-cash Operating, Investing and Financing Activities
Stock award plans
The accompanying notes are an integral part of the consolidated financial statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Summary of Significant Accounting Policies

     The Company's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in its 2001 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For interim reporting purposes, the Company follows these same basic accounting policies, but considers each interim period as an integral part of an annual period.

     The financial information included herein is unaudited; however, such information reflects all adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair statement of results for the interim periods.

Reclassifications: The Company will record reclassifications to the financial statements of the prior year when considered necessary or to conform to current year presentation. In the fourth quarter of 2001, Catamount Energy Corporation recorded $11.0 million of non-utility investments as held-for-sale, which have been reclassified from non-utility investments to investments held-for-sale. Also see Note 3 of Notes to Consolidated Financial Statements in the Company's 2001 Annual Report on Form 10-K, for additional information.

Note 2 - Regulatory Assets

     Certain costs are deferred and amortized in accordance with authorized or expected ratemaking treatment. The major components of regulatory assets reflected in the Consolidated Balance Sheet are as follows (dollars in thousands):

	March 31	December 31
	2002	2001
Conservation and load management (a)	$ 4,393	$ 4,633
Restructuring costs	44	59
Nuclear refueling outage costs (a)	3,017	4,445
Income taxes (b)	6,692	6,770
Dismantling costs (c):
Maine Yankee nuclear power plant	9,600	10,612
Connecticut Yankee nuclear power plant	4,275	4,513
Unrecovered plant and regulatory study costs	1,259	1,310
Other regulatory assets	109	61
	$29,389	$32,403
(a)  The Company earns a return on unamortized Conservation and Load Management costs and        replacement energy and maintenance costs related to scheduled nuclear refueling outages.
(b)  The net regulatory asset related to the adoption of SFAS No. 109 is recovered through tax        expense in the Company's cost of service generally over the remaining lives of the related property.
(c)  Recovery for the unamortized dismantling costs for Connecticut Yankee and Maine Yankee is       provided without a return on investment through 2007 and 2008, respectively.

     During regular nuclear refueling outages, in accordance with ratemaking treatment, the incremental costs attributable to replacement energy purchased from ISO-New England or other parties in New England, and maintenance costs, are deferred and amortized ratably to expense until the next regularly scheduled refueling outage.

During the first six months of 2001, Vermont Yankee and Millstone Unit #3 had scheduled refueling outages. The next scheduled refueling outages are October 2002 and September 2002 for Vermont Yankee and Millstone Unit #3, respectively.

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Note 3 - Investments in Affiliates

     The Company accounts for its investments in Vermont Yankee Nuclear Power Corporation ("Vermont Yankee") and Vermont Electric Power Company using the equity method. Summarized financial information is as follows (dollars in thousands):

Vermont Yankee Nuclear Power Corporation:

	Three Months Ended March 31
Earnings	2002	2001
Operating revenues	$38,731	$40,964
Operating income	$2,698	$3,458
Net income	$1,487	$1,550
Company's equity in net income	$509	$485

Vermont Electric Power Company:

	Three Months Ended March 31
Earnings	2002	2001
Transmission revenues	$6,484	$7,170
Operating income	$1,164	$740
Net income	$195	$243
Company's equity in net income	$83	$146

Note 4 - Retail Rates

     The Company recognizes that adequate and timely rate relief is necessary if it is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted.

Vermont Retail Rate Proceedings

     2000 Retail Rate Case: In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under-recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 24, 2001. The PSB suspended the rate filing and a schedule was set to review the case.

     On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision.

     The Company's June 26, 2001 rate order, which is described below, ended the uncertainty over the future recovery of Hydro-Quebec contract costs and the Company will no longer incur future losses for under-recovery of Hydro-Quebec contract costs related to any allegations of imprudence prior to the June 26, 2001 rate order.

     On May 7, 2001, the Company and the DPS reached a rate case settlement that would end uncertainty over the future recovery of Hydro-Quebec contract costs, allow a 3.95 % rate increase, make the January 1, 1999 temporary rates permanent, permit a return on equity of 11% for the twelve months ending June 30, 2002 for the Vermont utility, and create new service quality standards. The Company also agreed to a 2001 second quarter $9.0 million one-time write-off ($5.3 million after-tax) of regulatory assets and a rate freeze through January 1, 2003.

     On June 26, 2001, the PSB issued an order on the Company's rate case settlement with the DPS. In addition to the provisions outlined above, the approved rate order requires the Company to return up to $16.0 million to ratepayers in the event of a merger, acquisition or asset sale if such sale requires PSB approval. As a result of the rate order, the 3.95% rate increase became effective with bills rendered July 1, 2001, and in June 2001 the Company

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recorded a $5.3 million after-tax loss to write off certain regulatory assets as agreed to in the settlement. The Company was able to accept the 3.95% rate increase versus the 7.6% increase it requested since 1) regulatory asset amortizations will decrease approximately $3.5 million, on a twelve-month basis, due to the $9.0 million one-time write-off of regulatory assets and 2) Vermont Yankee decommissioning costs decreased approximately $1.9 million, on a twelve-month basis, after the rate case was filed as a result of an agreement in principle between Vermont Yankee and the secondary purchasers.

     As part of the Company's June 26, 2001 rate order, the Company agreed that all amounts collected from the Hydro-Quebec Ice Storm settlement shall be applied first to reduce the remaining balance of deferred costs related to this arbitration with the remaining balance, if any, applied to reduce other regulatory asset accounts as specified by the DPS and approved by the PSB. On July 19, 2001, Hydro-Quebec and the VJO agreed to a final settlement of the arbitration issues. Under the settlement, the VJO will continue to receive power and energy from Hydro-Quebec under this contract through 2016. As part of the settlement, Hydro-Quebec made a $9.0 million payment to the VJO in July 2001, of which the Company's share was approximately $4.3 million. In the third quarter of 2001, the Company applied approximately $2.7 million to the remaining balance of the deferred costs related to the ice storm arbitration. On October 30, 2001, the Company filed a letter with the PSB summarizing its agreement with the DPS on application of the remaining $1.6 million of the Hydro-Quebec settlement to remaining regulatory assets, which agreement is subject to approval by the PSB. Currently, the remaining $1.6 million balance is included as a deferred credit on the Company's Consolidated Balance Sheet.

New Hampshire Retail Rate/Federal Court Proceedings

     Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a Fuel Adjustment Clause ("FAC") and a Purchased Power Costs Adjustment ("PPCA"). Under these clauses, Connecticut Valley recovers its estimated annual costs for purchased energy and capacity, which are reconciled when actual data is available.

     In 1998, management determined that Connecticut Valley no longer qualified for the application of SFAS No. 71, and wrote off all of its regulatory assets associated with its New Hampshire retail business totaling approximately $1.3 million on a pre-tax basis. This determination was based on various legal and regulatory actions

including the February 28, 1997 NHPUC Final Plan to restructure the electric utility industry in New Hampshire, a supplemental order that required Connecticut Valley to give notice to cancel its power contract with the Company and denied stranded cost recovery related to this power contract, and a December 3, 1998 Court of Appeals decision stating that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. The Company's petition for rehearing with the Court of Appeals as well as petition for writ of certiorari with the United States Supreme Court were subsequently denied.

     As a result of the December 3, 1998 Court of Appeals decision, on March 22, 1999 the NHPUC issued an Order that directed Connecticut Valley to file its calculation of the difference between the total FAC and PPCA revenues that it would have collected had the 1997 FAC and PPCA rate levels been in effect the entire year. The NHPUC also directed Connecticut Valley to calculate a rate reduction to be applied to all billings for the period April 1, 1999 through December 31, 1999 to refund the 1998 over-collection relative to the 1997 rate level. The Company estimated this amount to be approximately $2.7 million on a pre-tax basis. On March 26, 1999, Connecticut Valley filed the required tariff page with the NHPUC, under protest and with reservation of all rights, and implemented the refund effective April 1, 1999.

     On April 7, 1999, the Federal District Court ("Court") ruled from the bench that the March 22, 1999 NHPUC Order requiring Connecticut Valley to provide a refund to its retail customers was illegal and beyond the NHPUC's authority. The Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates below rates in effect at December 31, 1997. Accordingly, Connecticut Valley removed the rate refund from retail rates effective April 16, 1999. The Court's decision was issued as a written order on May 11, 1999.

     On May 17, 1999, the NHPUC issued an order requiring Connecticut Valley to set temporary rates at the level in effect as of December 31, 1997, subject to future reconciliation, effective with bills issued on and after June 1, 1999. On May 24, 1999, the NHPUC filed a petition for mandamus in the Court of Appeals challenging the Court's May 11, 1999 ruling and seeking a decision allowing the refunds as required by the NHPUC's March 22, 1999 Order. The Court of Appeals denied that petition on June 2, 1999. The NHPUC immediately filed a notice of appeal in the Court of Appeals again challenging the Court's May 11, 1999 ruling. In that appeal, the Company and Connecticut Valley contended, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to

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purchase wholesale power from the Company in order to avoid the triggering of a FERC exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level which does not enable Connecticut Valley to recover all of these power costs.

     On June 14, 1999, Public Service Company of New Hampshire ("PSNH") and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached which was intended to result in a detailed settlement proposal to the NHPUC that would resolve PSNH's claims against the NHPUC's restructuring plan. On July 6, 1999, PSNH petitioned the Court to stay its proceedings related to electric utility restructuring in New Hampshire indefinitely while the proposed settlement was reviewed and approved by the NHPUC and the New Hampshire Legislature. On July 12, 1999, the Company and Connecticut Valley objected to any stay that would allow the NHPUC's rate freeze order to remain in effect for an extended period and asked the Court to proceed with prompt hearings on its summary judgement motion and trial on the merits. On October 20, 1999, the Court heard oral arguments pertaining to the pretrial motions of the Company and the NHPUC for summary judgement and dismissal.

     On December 1, 1999, Connecticut Valley filed with the NHPUC a petition for a change in its FAC and PPCA rates effective on bills rendered on and after January 1, 2000. On December 30, 1999, the NHPUC denied Connecticut Valley's request to increase its FAC and PPCA rates above those in effect at December 31, 1997, subject to further investigation and reconciliation until otherwise ordered by the NHPUC. Accordingly, during the fourth quarter of 1999, Connecticut Valley recorded a pre-tax loss of $1.2 million for under-collection of year 2000 power costs.

     The Court of Appeals issued a decision on January 24, 2000, which upheld the Court's preliminary injunction enjoining the Commission's restructuring plan. The decision also remanded the refund issue to the Court stating:

"the district court may defer vacation of this injunction against the refund order for up to 90 days. If within that period it has decided the merits of the request for a permanent injunction in a way inconsistent with refunds, or has taken any other action that provides a showing that the Company is likely to prevail on the merits in federal court in barring the refunds, it may enter a superseding injunction against the refund order, which the Commission may then appeal to us. Otherwise, no later than the end of the 90-day period, the district court must vacate its present injunction insofar as it enjoins the Commission's refund order."

     On March 6, 2000, the Court granted summary judgement to Connecticut Valley and the Company on their claim under the filed-rate doctrine and issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the rate schedule with the Company. The Court also ruled that Connecticut Valley was entitled to recover the wholesale costs that the NHPUC disallowed in retail rates since January 1, 1997.

     Pursuant to the March 6, 2000 Court Order, on March 17, 2000, Connecticut Valley filed a rate request with the NHPUC for an Interim FAC/PPCA to recover the balance of wholesale costs not recovered since January 1997. To mitigate the rate increase percentage, the Interim FAC/PPCA was designed to recover current power costs and a substantial portion of past under-collections by the end of 2000; the remainder of the past under-collections were being collected during 2001 along with 2001 power costs. The NHPUC held a hearing on April 7, 2000 to review the 12.3% increase that would raise $1.6 million of revenues in 2000. The NHPUC issued an order approving the rates as temporary effective May 1, 2000.

     On July 25, 2000, the Court of Appeals affirmed the Court's March 6, 2000 Order granting summary judgement to Connecticut Valley and the Company. The NHPUC then asked the Court of Appeals to reconsider its decision. That request was denied. As a result of the favorable Court of Appeals action, Connecticut Valley recorded a $2.0 million after-tax gain in the third quarter of 2000. On November 27, 2000, the NHPUC filed a petition for writ of certiorari with the United States Supreme Court. On February 20, 2001, the Supreme Court denied the petition for writ of certiorari, thus leaving the Court of Appeals approval of the permanent injunction intact.

     In the third quarter of 2001, Management determined that Connecticut Valley is again subject to cost-based ratemaking and qualifies for the application of SFAS No. 71. This decision was based on the favorable Court of Appeals decision of July 25, 2000 and the subsequent denial of the NHPUC's petition for writ of certiorari by the United States Supreme Court on February 20, 2001 as well as other regulatory developments in New Hampshire during 2001. The application of SFAS No. 71 resulted in an extraordinary charge of $0.2 million for Connecticut Valley.

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     As part of its restructuring plan, the New Hampshire Legislature enacted an Electricity Consumption Tax on customers and repealed the New Hampshire Franchise Tax on utilities, both of which became effective May 1, 2001. Since the Franchise Tax, as a credit to the New Hampshire Business Profits Tax, was larger than the Business Profits Tax, the repeal of the Franchise Tax caused Connecticut Valley to incur the Business Profits Tax. The NHPUC approved a settlement that reduced base rates to remove recovery of the Franchise Tax and implemented a Business Profits Tax Percentage Adjustment that would be subject to annual revisions in order to collect the Business Profits Tax.

     On December 31, 2001, the NHPUC ruled on Connecticut Valley's request for a Temporary Billing Surcharge to recover approximately $1.7 million of one-time costs primarily related to industry restructuring effective January 1, 2002. Connecticut Valley had proposed the Temporary Billing Surcharge to exactly offset a contemporaneously filed FAC/PPCA decrease of 9.3% such that a zero rate change would occur at January 1, 2002 and the 9.3% FAC/PPCA decrease would occur when the Temporary Billing Surcharge terminated in November 2002. The NHPUC affirmed its prior policy of considering recovery of costs related to industry restructuring at the time retail choice is implemented in the Connecticut Valley service area. Thus the NHPUC deferred action on all but $125,000, for which recovery was allowed through November 30, 2002.

     On December 31, 2001 the NHPUC approved Connecticut Valley's FAC and PPCA rates for 2002 as well as Connecticut Valley's Business Profits Tax Adjustment Percentage and Conservation and Load Management Percentage Adjustment for 2002. Combined with the Temporary Billing Surcharge, the result was an overall 8.6% rate reduction with a revenue decrease of $1.8 million.

     The New Hampshire electric utilities will begin delivery of consistent, statewide energy efficiency programs by the middle of 2002. The NHPUC approved the design of common, core efficiency programs. By filing letter dated February 27, 2002, Connecticut Valley proposed implementation of several specific, non-core energy efficiency programs and recovery of costs for all the energy efficiency programs via an Interim 2002 - 2003 Conservation and Load Management Percentage Adjustment (C&LMPA) effective June 1, 2002 in accordance with NHPUC Order No. 23,850. Connecticut Valley had ceased providing such programs in 1997. The proposal would raise rates by an average 1.4-%. Negotiations have been ongoing and a hearing is scheduled for May 15, 2002.

FERC Proceedings

     On February 28, 1997, Connecticut Valley was directed by the NHPUC to terminate its purchase of power from the Company. The Company filed an application with the FERC in June 1997, to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and the notice of cancellation of that rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of that rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge in the Company's transmission tariff, but indicated that it would consider an exit fee mechanism in the wholesale rate schedule for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the transmission surcharge proposal. However, the Company filed a request with the FERC for an exit fee mechanism in the wholesale rate schedule to collect the stranded costs resulting from the

cancellation of the wholesale rate schedule. The stranded cost obligation sought to be recovered was $90.6 million in nominal dollars and $44.9 million on a net present value basis as of December 31, 1997.

     On April 24, 2001, a FERC Administrative Law Judge ("ALJ") issued an Initial Decision in the Company's stranded cost/exit fee proceeding. The ALJ ruled that if Connecticut Valley terminates its relationship as a wholesale customer of the Company and subsequently becomes a wholesale transmission customer of the Company, Connecticut Valley shall be liable for payment of stranded costs to the Company. The ALJ calculated, on an illustrative pro-forma basis, a nominal stranded cost obligation of nearly $83.0 million through 2016. The amount of the exit fee as determined by the ALJ will decrease with each year that service continues and normal tariff revenues are collected, and will ultimately be calculated from the date of termination, if notice of termination is ever given. Absent termination of the wholesale rate schedule by mutual agreement, the earliest termination date that could presently occur pursuant to the wholesale rate schedule is December 31, 2003. The stranded cost obligation as of December 31, 2003, expressed on a net present value basis set forth in the ALJ order, is approximately $33.9 million.

     The ALJ's Initial Decision is subject to review and approval by the FERC. If the Company is unable to obtain approval by the FERC, and if Connecticut Valley is forced to terminate its relationship as a wholesale customer of the Company, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $32.9 million as of December 31, 2003. The Company would also be required to write-off

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approximately $0.8 million (pre-tax) of regulatory assets associated with its wholesale business as of December 31, 2003. If the Company obtains a FERC order authorizing the updated requested exit fee and notice of termination is given, Connecticut Valley will apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs in rates, Connecticut Valley would be required to recognize the loss discussed above.

     In addition to its efforts before the Court and FERC, Connecticut Valley has initiated efforts and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC.

     An adverse resolution of the FERC and New Hampshire proceedings would have a material adverse effect on the Company's results of operations and cash flows. However, the Company cannot predict the ultimate outcome of this matter.

Wheelabrator Power Contract

     Connecticut Valley purchases power from several Independent Power Producers, who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2001, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 38,890 mWh, of which 96% was purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a waste-to-energy electric generating facility. Connecticut Valley had filed a complaint with the FERC stating its concern that Wheelabrator has not been a qualifying facility since the facility began operation. On February 11, 1998, the FERC issued an Order denying Connecticut Valley's request for a refund of past purchased power costs and lower future costs. Connecticut Valley filed a request for rehearing with the FERC on March 13, 1998, which was denied. Connecticut Valley appealed to the D.C. Circuit Court of Appeals, which denied the appeal, but indicated that Connecticut Valley could seek relief from the NHPUC. On May 12, 2000, Connecticut Valley filed a petition with the NHPUC seeking 1) to amend the contract to permit purchase of net, rather than gross, output of the facility and 2) a refund, with interest, of past purchases of the difference between net and gross output.

     In December 2000 and January 2001, Wheelabrator, the New Hampshire/Vermont Solid Waste District, and several Connecticut Valley residential customers filed with the NHPUC to intervene. The Office of Consumer Advocate and the NHPUC Staff are automatic parties. A Prehearing Conference was held before the NHPUC on January 4, 2001, at which time each party provided preliminary position statements with regard to the petition. In February and March 2001, the parties filed briefs on the legal issues and Wheelabrator filed a motion to dismiss. The Company cannot predict when the NHPUC will issue a decision on the legal issues.

     On March 29, 2002, the NHPUC issued an order denying Connecticut Valley's petition. The NHPUC further found that its original 1983 order did not authorize sales in excess of 3.6 MW and ordered that Connecticut Valley discontinue purchases in excess of that amount at preferential rates. Wheelabrator has been making sales at the long-term rates for up to 4.5 MW of capacity and related energy since it began operations in 1987. The NHPUC scheduled a status conference in mid May 2002 for the purpose of establishing a proceeding to determine whether Connecticut Valley, Wheelabrator or both parties were responsible for any of the alleged overcharges associated with the purchases in excess of 3.6 MW at the approved long-term rates.

     On April 29, 2002, Connecticut Valley, Wheelabrator, NHPUC Staff and the Office of Consumer Advocate submitted a Stipulation of Settlement with the NHPUC that requires Wheelabrator to make five annual payments of $150,000 and a sixth payment of $25,000, and Connecticut Valley to make six annual payments of $10,000, all of which will be credited to customer bills. The Stipulation of Settlement will not become effective unless and until it is approved by the NHPUC. The settlement does not otherwise change the terms of the existing contract between Connecticut Valley and Wheelabrator.

Note 5 - Environmental

     The Company is engaged in various operations and activities which subject it to inspection and supervision by both federal and state regulatory authorities including the United States Environmental Protection Agency ("EPA"). It is Company policy to comply with all environmental laws. The Company has implemented various procedures and internal controls to assess and assure compliance. If non-compliance is discovered, corrective action is taken. Based on these efforts and the oversight of those regulatory agencies having jurisdiction, the Company believes it is in compliance, in all material respects, with all pertinent environmental laws and regulations.

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     Company operations occasionally result in unavoidable, inadvertent releases of regulated substances or materials; for example, the rupture of a pole-mounted transformer or a broken hydraulic line. Whenever the Company learns of such a release, the Company responds in a timely fashion and in a manner that complies with all federal and state requirements. Except as discussed in the following paragraphs, the Company is not aware of any instances where it has caused, permitted or suffered a release or spill on or about its properties or otherwise which is likely to result in any material environmental liabilities to the Company.

     The Company is an amalgamation of more than 100 predecessor companies. Those companies engaged in various operations and activities prior to being merged into the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at four different locations. The Company discontinued these activities in the late 1940s or early 1950s. The coal gas manufacturers, other predecessor companies and the Company itself may have engaged in waste disposal activities which, while legal and consistent with commercially accepted practices at the time, may not meet modern standards and thus represent potential liability.

     The Company continues to investigate, evaluate, monitor and, where appropriate, remediate contaminated sites related to these past activities. The Company's policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated. As part of that process, the Company also researches the possibility of insurance coverage that could defray any such remediation expenses.

Cleveland Avenue Property The Company's Cleveland Avenue property, located in the City of Rutland, Vermont, was a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl ("PCB") contamination and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980s and early 1990s to determine the magnitude and extent of the contamination. After completing its preliminary investigation, the Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5.0 million. This was charged to expense in the fourth quarter of 1992. Site investigation has continued over the last several years and the Company continues to work with the State of Vermont in a joint effort to develop a mutually acceptable solution.

Brattleboro Manufactured Gas Facility From the early to late 1940s, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company commissioned an environmental site assessment in late 1999 upon request by the State of New Hampshire. In early 2001, the Company submitted a work plan to the State of New Hampshire to address their concerns and in October 2001 the Company received a Certificate of No Further Action from the State of New Hampshire; however, the State reserves the right to require additional investigation or remedial measures, if necessary. In the third quarter of 2001, the Company submitted a corrective action plan to the State of Vermont. On January 17, 2002, the Company received a letter from the Vermont Agency of Natural Resources notifying the Company that its corrective action plan for the site is approved. The Company is now implementing the corrective action plan, which includes provisions for periodic groundwater monitoring and institutional controls.

Dover, New Hampshire, Manufactured Gas Facility In late 1999, the Company was contacted by PSNH with respect to this site. PSNH alleged the Company is partially liable for remediation of this site. PSNH's allegation is premised on the fact that prior to PSNH's purchase of the facility, it was operated by Twin State Gas and Electric ("Twin State"). Twin State merged with the Company on the same day the facility was sold to PSNH. The Company and PSNH agreed to and have already participated in a non-binding mediation to further investigate the terms and conditions surrounding the sale of the plant to PSNH and Twin State's merger into the Company.

     In December 2000, PSNH submitted a work plan to the State of New Hampshire for further investigation of this site. The Company agreed, with reservations, to participate on a limited basis in the development and completion of the work plan since the State of New Hampshire considers the Company, along with others, as potentially responsible parties at the site. The Company, PSNH and Keyspan Energy hired a contractor, which completed the fieldwork in October 2001. A report will be published and submitted to the State of New Hampshire by June 2002. Shortly thereafter, the Company and others will begin evaluating remediation options for the site.

     Having previously agreed to non-binding mediation, a mediator on the issue of liability was chosen in April 2001 and the first phase of mediation, or "Phase I", concluded on July 18, 2001. Without admitting liability, both the Company and PSNH agreed to participate in the site remediation for those years that Twin State and PSNH were

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responsible. On October 30 and 31, 2001, the Company and PSNH met with others in a "Phase II" mediation process. The subject of the Phase II mediation was the liability of other potentially responsible parties at the site, in particular those that owned the property after Twin State and PSNH. The Phase II mediation process did not achieve the goal of a general agreement on liability between the participants. In the first quarter of 2002, Phase II negotiations continued but did not achieve the goal of a general agreement on liability between the participants.

     The Company is not subject to any pending or threatened litigation with respect to any other sites that have the potential for causing the Company to incur material remediation expenses, nor has the EPA or any other federal or state agency sought contribution from the Company for the study or remediation of any such sites.

     As of March 31, 2002, a reserve of $9.3 million has been established representing management's best estimate of the costs to remediate the sites discussed above.

Note 6 - Redeemable Preferred Stock

The 8.3% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum and, at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum. The Company paid the mandatory sinking fund payment in the amount of $1.0 million in the first quarter of 2002.

Note 7 - Segment Reporting

     The Company's reportable operating segments include Central Vermont Public Service Corporation ("CV"), which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; Connecticut Valley Electric Company Inc. ("CVEC"), which distributes and sells electricity in parts of New Hampshire; Catamount Energy Corporation ("Catamount"), which has investments in non-regulated, energy-supply projects in the United States and Western Europe; and Eversant Corporation ("Eversant"), which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of electric water heaters to customers in Vermont and New Hampshire and as of March 31, 2002, had a 12.6% ownership interest, on a fully diluted basis, in the Home Services Store ("HSS"), operating nationwide.  The Company has decided to discontinue Eversant's efforts to pursue non-regulated business opportunities. CVEC, while managed on an integrated basis with CV, is presented separately because of its separate and distinct regulatory jurisdiction. Other operating segments include a segment below the quantitative threshold for separate disclosure. This operating segment is

C. V. Realty, Inc., a real estate company whose purpose is to own, acquire, buy, sell and lease real and personal property and interests therein related to the utility business. Information for 2001 has been restated to include equity income.

     The accounting policies of the operating segments are the same as those described in the summary of significant accounting policies. Intersegment revenues include sales of purchased power to CVEC and revenues for support services to CVEC, Catamount and Eversant.

     The intersegment sales and services for each jurisdiction are based on actual rates or current costs. The Company evaluates performance based on stand-alone operating segment net income. Financial information by industry segment for the three months ended March 31, 2002 and 2001 is as follows (dollars in thousands):

					Reclassification
	CV	CVEC			and Consolidating
	VT	NH	Catamount	Eversant	Other (1)	Entries	Consolidated
2002
Revenues from external customers	$  71,713	$  4,766	$     241	$    424	-	$    669	$  76,475
Intersegment revenues	2,525	-	-	-	-	2,525	-
Equity income - utility affiliates	634	-	-	-	-	-	634
Equity income - non-utility affiliates	-	-	2,567	-	-	2,567	-
Net income (loss)	4,874	71	452	(614)	$    1	-	4,784
Total assets	448,000	11,897	58,359	4,383	322	3,835	519,126
2001
Revenues from external customers	$  72,492	$  5,541	$      53	$    491	-	$    545	$  78,032
Intersegment revenues	3,181	-	-	-	-	3,181	-
Equity income - utility affiliates	662	-	-	-	-	-	662
Equity income - non-utility affiliates	-	-	1,521	-	-	1,521	-
Net income (loss)	3,596	106	356	(163)	$    2	-	3,897
Total assets	479,515	12,262	53,981	6,153	316	4,795	547,432

(1)     Includes a segment below the quantitative threshold.

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Note 8 - Recent Accounting Pronouncements

Derivative Instruments: On January 1, 2001, the Company adopted SFAS No. 133 (subsequently amended by SFAS No. 137 and 138), Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"). This Statement, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

     The Company has one long-term purchase power contract that allows the seller to purchase specified amounts of power with advance notice (Hydro-Quebec Sellback #3). This contract has been determined to be a derivative under SFAS No. 133. On April 11, 2001, the PSB approved an Accounting Order that allows the fair valuation adjustment of this contract to be deferred on the balance sheet as either a deferred asset or liability. At March 31, 2002, this derivative had an estimated fair market value of approximately a $1.0 million unrealized loss, which is included in Other deferred credits on the Consolidated Balance Sheet along with an offsetting deferred asset which is included in Other deferred charges.

Goodwill and Other Intangible Assets: In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"), effective for fiscal years beginning after December 15, 2001. SFAS No. 142 establishes a new accounting standard for the treatment of goodwill. The new standard continues to require recognition of goodwill as an asset in a business combination but does not permit amortization as is done under current accounting standards. Effective January 1, 2002, SFAS No. 142 requires that goodwill be separately tested for impairment using a fair-value based approach as opposed to the undiscounted cash flow approach used under current accounting standards. If goodwill is found to be impaired, the Company would be required to record a non-cash charge against income, which would be recorded as a cumulative effect of a change in accounting principle. The impairment charge would be equal to the amount by which the carrying amount of the goodwill exceeds its estimated fair value. The Company has no goodwill related to its regulated businesses, however, Catamount has net intangible assets of approximately $2.0 million related to four of its investments. There was no material financial statement impact resulting from the Company's implementation of SFAS No. 142 in the first quarter of 2002.

Asset Retirement Obligations: In August 2001, the FASB approved the issuance of SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). This statement provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of long-lived assets and requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company has identified potential retirement obligations associated with the decommissioning of its nuclear facilities, but has not yet completed its assessment. This statement is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company has not yet quantified the impacts, if any, of adopting SFAS No. 143 on its financial statements.

Impairment or Disposal of Long-Lived Assets: In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144") which replaces SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. Although SFAS No. 144 supercedes SFAS No. 121, it retains the fundamental provisions of SFAS No. 121 regarding

recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. Under SFAS No. 144, asset write-downs from discontinuing a business segment will be treated the same as other assets held for sale. The new standard also broadens the financial statement presentation of discontinued operations to include the disposal of an asset group (rather than a segment of a business). SFAS No. 144 is effective beginning January 1, 2002 and, generally, is to be applied prospectively. The Company adopted SFAS No. 144 in the first quarter of 2002, and there was no material impact on its financial statements.

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CENTRAL VERMONT PUBLIC SERVICE CORPORATION

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

     This discussion should be read in conjunction with the consolidated financial statements and footnotes in this Form 10-Q, current reports on Form 8-K dated March 4, 2002, and March 22, 2002, and the 2001 Form 10-K.

Forward-Looking Statements Statements contained in this report that are not historical fact (including Management's Discussion and Analysis of Financial Condition and Results of Operations) are forward-looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Reform Act of 1995. Statements made that are not historical facts are forward-looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Actual results will depend, among other things, upon the actions of regulators, the outcome of litigation at the Federal Energy Regulatory Commission ("FERC") involving the Company's regulated companies, the performance of the Vermont Yankee nuclear power plant ("Vermont Yankee"), weather conditions, the performance of the Company's non-regulated businesses and the state of the economy in the areas served. The Company cannot predict the outcome of any of these matters.

Critical Accounting Policies

     Preparation of the Company's financial statements in accordance with generally accepted accounting principles requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities and revenues and expenses. Note 1 in the Company's 2001 Form 10-K to the Consolidated Financial Statements is a summary of the significant accounting policies used in the preparation of the Company's financial statements. The following is a discussion of the most critical accounting policies used by the Company.

Regulation The Company is subject to regulation by the Vermont Public Service Board, the New Hampshire Public Utilities Commission and the FERC, with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation", or SFAS No. 71, for both its regulated service territories and FERC-regulated wholesale businesses. In order for a company to report under SFAS No. 71, the Company's rates must be designed to recover its costs of providing service and must be able to collect those rates from customers. If rate recovery becomes unlikely or uncertain, whether due to competition or regulatory action, this accounting standard would no longer apply to the Company's regulated operations. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material. Management periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, Management believes future recovery of its regulatory assets in the State of Vermont and the State of New Hampshire for the Company's retail and wholesale businesses are probable.

Valuation of Long-Lived Assets The Company periodically evaluates the carrying value of long-lived assets and long-lived assets to be disposed of, including its investments in nuclear generating companies, its unregulated investments, and its interests in jointly owned generating facilities, when events and circumstances warrant such a review. The carrying value of such assets is considered impaired when the anticipated undiscounted cash flow from such an asset is separately identifiable and is less than its carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Based on Management's review, certain of Catamount's investments were impaired at December 31, 2001. See Diversification below for further discussion.

Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts do not convey to the Company the right to use property, plant or equipment, they are considered executory in nature.

Other Other significant accounting policies include: 1) estimated unbilled revenues recorded at the end of each quarterly accounting period; 2) depreciation based on the straight-line remaining life method; and 3) income taxes recorded in accordance with SFAS No. 109, "Accounting for Income Taxes."

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Earnings Overview

     The Company reported net income of $4.8 million, or $.38 per basic and $.37 per diluted share of common stock, for the first quarter of 2002 compared to net income of $3.9 million, or $.30 per basic and diluted share of common stock, for the first quarter of 2001. Higher first quarter 2002 earnings compared to the same period in 2001 resulted from the following factors:

          higher retail sales revenue of $0.6 million after-tax, or $.05 per share of common stock, primarily resulting
          from higher average retail rates due to the June 26, 2001 rate order which allowed for a 3.95% increase in
          retail rates beginning July 1, 2001, offset by a 1.3% (8,029 mWh) decrease in retail mWh sales related to
          milder weather in 2002;

          higher net power costs of $0.1 million after-tax, or $.01 per share of common stock, resulting from lower
          short-term market prices in ISO-New England for resale sales;

          lower operating and other costs of $0.9 million after-tax, or $.08 per share of common stock, related to lower
          storm restoration costs compared to the first quarter of 2001 and lower costs associated with CV's share of
          Millstone Unit 3; and

          higher losses at Eversant Corporation of $0.4 million after-tax, or $.04 per share of common stock, primarily
          related to the Company's decision to discontinue Eversant's efforts to pursue non-regulated business
          opportunities.

     Other factors affecting results for the first quarter of 2002 are described in the following Results of Operations.

Results of Operations

The major elements of the Consolidated Statement of Income are discussed below.

Operating revenues and megawatt-hour ("mWh") sales A summary for 2002 and 2001 follows:

Three Months Ended March 31
				Percentage					Percentage
	mWh Sales			Increase		Revenues (000's)			Increase
	2002	2001	(Decrease)		2002		2001	(Decrease)
Residential	265,287	273,396	(3.0)		$34,337		$34,370	(0.1)
Commercial	228,912	232,346	(1.5)		26,909		26,353	2.1
Industrial	117,780	114,254	3.1		9,910		9,419	5.2
Other retail	1,530	1,542	(0.8)		437		436	0.2
Total retail sales	613,509	621,538	(1.3)		71,593		70,578	1.4
Resale sales:
Firm	558	674	17.3		33		38	(13.1)
Entitlement	-	53,121	(100.0)		-		1,969	(100.0)
Other	121,272	81,427	49.0		3,364		3,812	(11.8)
Total resale sales	121,830	135,222	(9.9)		3,397		5,819	(41.6)
Other revenues	-	-			1,485		1,635
Total	735,339	756,760	(2.8)		$76,475		$78,032	(2.0)

     Retail sales revenue increased $1.0 million, or 1.4%, for the first quarter of 2002 compared to the first quarter of 2001, while retail mWh sales decreased 1.3% over the same period. The increase in retail sales revenue resulted from the 3.95% retail rate increase, which became effective July 1, 2001, and the decrease in retail mWh is primarily related to milder weather in the first quarter of 2002 compared to the same period in 2001.

     Entitlement sales in 2001 were related to a five-year power contract in which the Company sold approximately 15% of its share of Vermont Yankee output at full cost; that contract ended in October 2001. The additional output that the Company receives from Vermont Yankee due to the discontinuance of this contract is either used to support its own-load needs or sold in the short-term market mostly to ISO-New England.

     Other resale sales increased 49% for the first quarter of 2002 compared to the first quarter of 2001, due to the end of both the Vermont Yankee entitlement sale and certain Hydro-Quebec purchases described below. However, other resale sales revenue decreased $0.4 million due to significantly lower short-term market rates in ISO-New England.

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Net Purchased Power and Production Fuel The net cost components of purchased power and production fuel costs for the three months ended March 31, 2002 and 2002 are as follows (dollars in thousands):

	2002		2001
	Units	Amount	Units	Amount
Purchased and produced:
Capacity (mW)	450	$21,893	439	$22,384
Energy (mWh)	691,409	15,721	742,627	17,065
Total purchased power costs		37,614		39,449
Production fuel (mWh)   Total purchased power and production fuel costs	98,211	571 38,185	70,651	956 40,405
Less entitlement and other resale  sales (mWh)	121,272	3,364	134,548	5,781
Net purchased power and production  fuel costs		$34,821		$34,624

     For the first quarter of 2002, purchased capacity decreased $0.5 million compared to 2001 due to lower priced capability (ICAP) purchases, a reduction in payments to Hydro-Quebec, and lower Vermont Yankee costs, partially offset by higher volume ICAP purchases.

     Energy purchases for the first quarter of 2002 decreased $1.3 million primarily due to certain purchases made in 2001 but not in 2002, including Hydro-Quebec 9600, a contract in which the Company purchased power from Hydro-Quebec and resold the power in ISO-New England, and the Hydro-Quebec Firm Energy Contract, which expired in 2001. Offsetting these were increased purchases from the Independent Power Producers due to higher volume. Additionally, Vermont Yankee mWh purchases increased due to an increase in the Company's entitlement share, which began in March 2002, while its energy costs decreased slightly due to a reduction in the fuel rate.

     Production fuel costs decreased $0.4 million compared to 2001 primarily due to fewer purchases from the Wyman and McNeil generating stations in 2002. In 2001, the Company purchased more from those generating stations, as a result of the first quarter 2001 Millstone Unit #3 scheduled refueling outage.

NUCLEAR MATTERS

     The Company maintains a 1.7303% joint-ownership interest in Unit #3 of the Millstone Nuclear Power Station and owns a 2%, 2% and 3.5% equity interest in Connecticut Yankee, Maine Yankee and Yankee Atomic, respectively. In the first quarter of 2002, the Company's ownership percentage of Vermont Yankee changed from 31.3% to 33.23% related to the repurchase of shares held by minority owners of the plant, which is explained in more detail below.

Millstone Unit #3

     On March 31, 2001, the sale of Millstone Unit #3 to Dominion Nuclear Connecticut ("DNC"), a subsidiary of Dominion Resources, Inc., became final. Millstone Unit #3 continues to be a jointly owned plant, and the Company is one of two minority owners, however the total DNC share is 93.4707%.

     As part of the regulatory approvals of the sales to DNC by the joint owners of that plant, DNC has represented to the Nuclear Regulatory Commission ("NRC") and other regulatory bodies, including the Connecticut Department of Public Utility Control, that the Millstone Unit #3 Decommissioning Trust Fund, for its share of the plant, exceeds the NRC minimum calculation required and therefore no further contributions to the fund are required at this time. The Company has agreed with the DPS position in its recent rate case that the DNC representation that contributions currently can cease is appropriate subject to periodic review of both the fund balance and the NRC minimum calculation upon which the DNC bases its assertion of fund adequacy. The Company could choose to renew funding at its own discretion as long as the minimum requirement is met or exceeded.

Vermont Yankee

     The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, began a scheduled refueling outage on April 27, 2001, which ended on May 20, 2001, 11 days shorter than budgeted. The previous refueling outage began on October 29, 1999 and the plant returned to service December 2, 1999. The 1998 refueling outage (March 21-June 3) extended 26 days beyond the scheduled 49 days. The next scheduled refueling outage is October 2002.

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     On August 15, 2001, Vermont Yankee announced that a sales agreement had been reached with Entergy Corporation ("Entergy") for $180 million, representing $145 million for the plant and related assets and $35 million for nuclear fuel. Entergy will also assume decommissioning liability for the plant and its decommissioning trust fund. The agreement includes a purchase power contract with prices that generally range from 3.9 cents to 4.5 cents per kilowatt-hour subject to a "low-market adjuster" that protects the current Vermont Yankee owner-utilities, including the Company and its power consumers, in the event power market prices drop significantly. On September 27, 2001, the Company filed testimony with the PSB in support of the sale. In an order entered October 26, 2001, the PSB granted intervention to several parties that the Company did not oppose, and established a schedule that provided for discovery, hearings and final briefing by April 29, 2002. Certain of the intervenors were secondary purchasers of Vermont Yankee power, which were seeking adjustments in their power purchase contracts, and stockholders of Vermont Yankee, which were asserting dissenters' rights. On January 16, 2002, Vermont Yankee announced that it had reached an agreement with the secondary purchasers and had repurchased back the shares held by the minority stockholders; these parties have requested to withdraw from the PSB proceeding.

     Following hearings on February 4 - 8 and 14 - 15, 2002, the Company, Green Mountain Power ("GMP"), Vermont Yankee and Entergy filed rebuttal testimony. On March 6, 2002, the Company, GMP, Vermont Yankee, Entergy and the Department of Public Service filed a joint Memorandum of Understanding (MOU) that resolved all issues raised by the DPS earlier in the proceeding and in which the MOU parties recommend approval of the sale in accordance with the terms of the MOU. The intervenors did not join in the MOU. During April 2002, the Board held hearings on the rebuttal testimony of all parties as well as the MOU.

     Initial Briefs were filed by all parties on May 7, 2002, with Reply Briefs being filed on May 14, 2002. The revised schedule anticipates a Board order in June 2002, to allow for a closing, if the transaction is approved, by July 31, 2002, which is the last day for closing provided in the Purchase and Sale Agreement between Entergy and Vermont Yankee. While the Company believes the sale is in the best interest of the state and of the Company's ratepayers, the Company cannot predict whether the sale will be approved by the Board.

     The sale is also subject to other regulatory approvals including the Nuclear Regulatory Commission and the Securities and Exchange Commission.

     The Vermont Yankee plant currently has several fuel assemblies containing potentially defective fuel rods. These, and any other affected fuel assemblies, are expected to be replaced during a 10- to 14-day outage in May 2002. The costs associated with this outage may be material and the current estimated range is from $3.0 million to $6.8 million for the Company's share of incremental costs. Actual costs could differ from this estimate by a material amount based on the duration of the outage, the extent of necessary repairs and the purchase price of replacement power during the outage period. The Company intends to request an Accounting Order from the PSB to defer these incremental costs for inclusion in rates at the next retail rate case.

Maine Yankee

     On August 6, 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5% of its required system capacity. The decommissioning effort continues per project plans. The total expected decommissioning costs for Maine Yankee are $536.0 million in 1998 dollars. The original decommissioning contractor, Stone and Webster, filed for bankruptcy and, in January 2002, Maine Yankee and Federal Insurance agreed on a settlement of the pending litigation arising from contract performance when Stone and Webster went into bankruptcy. A settlement payment of $44.0 million has been deposited into the Maine Yankee Decommissioning Trust Fund. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee, including the insurance settlement are currently estimated to be approximately $494.2 million; the Company's share is expected to be approximately $9.9 million to be paid over the period 2002 through 2008.

Connecticut Yankee

     On December 4, 1996, the Connecticut Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Connecticut Yankee for less than 3% of its required system capacity. Connecticut Yankee continues to decommission the site. Connecticut Yankee reached a settlement with the FERC and the intervenors that allows for the cost recovery of the total expected decommissioning costs now estimated at $569.0 million in January 2000 dollars, as well as other appropriate costs of service. The settlement rates became effective September 1, 2000, following the FERC order of July 26, 2000. Connecticut Yankee is required to commence a new filing before the FERC no later than July 1, 2004 to review the status of decommissioning

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expenditures, the expected remaining decommissioning costs and their collections, and other appropriate issues. Future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee are currently estimated to be approximately $226.6 million; the Company's share is expected to be approximately $4.5 million to be paid over the period 2002 through 2007.

Yankee Atomic

     In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5% of its system capacity. As of July 2000, Yankee Atomic had collected from its sponsors sufficient funds, based on a current forecast, to complete the decommissioning effort and to recover all other FERC-approved costs of service. Therefore, Yankee Atomic discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations, including decommissioning. Such a change would require a FERC review and approval. Yankee Atomic is successfully decommissioning the site as planned.

Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs

     Currently, costs billed to the Company by Maine Yankee and Connecticut Yankee, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. As of December 31, 2000, the Company completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation were estimated to be $9.6 million and $4.3 million, respectively, at March 31, 2002. These amounts are subject to ongoing review and revisions and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current).

     The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. This would have the effect of lowering costs to customers. The Company believes that based on the current regulatory process, its proportionate share of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the three plants has not and should not have a material adverse effect on the Company's earnings or financial condition.

     The Company is responsible for paying its entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee Atomic, as well as its joint-ownership percentage of decommissioning costs for Millstone Unit #3. The staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry, including the Company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board ("FASB") issued a new accounting pronouncement related to asset retirement obligations that includes decommissioning of nuclear power plants. See discussion of Recent Accounting Pronouncements above.

Cogeneration/Independent Power Qualifying Facilities

     The Company purchases power from a number of Independent Power Producers ("IPPs") who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, biomass and refuse-burning generation. The majority of these purchases are made from a state-appointed purchasing agent who purchases and redistributes the power to all Vermont utilities. Under these long-term contracts, in 2001, the Company received 168,382 mWh of which 118,187 mWh is associated with the Vermont Electric Power Producers and 37,293 mWh from a waste-to-energy electric generating facility owned by Wheelabrator Claremont Company, L.P.

     On August 3, 1999, the Company, GMP, Citizens Utilities and all of Vermont's 15 municipal utilities filed a petition with the PSB requesting modification of the contracts between the IPPs and the state-appointed purchasing agent. The petition outlined seven specific elements that, if implemented, would reduce purchase power costs and reform these contracts for the benefit of consumers. On September 3, 1999, the PSB opened a formal investigation in Docket No. 6270 regarding these contracts as requested by the Petition. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and Burlington Electric Department notified the PSB that they were withdrawing from the Petition but would participate in the case as non-moving parties. In a separate action before the Chittenden County Superior Court brought by several IPP owners, GMP's full participation in this PSB proceeding was enjoined and that injunction has since been appealed to and affirmed by the Vermont Supreme Court.

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     On November 22, 2000, the IPPs filed dispositive motions in Docket No. 6270, urging the PSB to declare that it lacks jurisdiction to grant relief sought by the Company's Petition. On September 18, 2001, the PSB issued an Order regarding jurisdiction finding that it has jurisdiction to consider the relief sought under the Petition but that it is precluded from issuing orders reducing the lengths of a Purchasing Agent contract or requiring buy-outs or buy-downs.

     The IPPs also filed a related proceeding in the Washington County Superior Court contending that the PSB rules pertaining to IPPs, which the utilities have relied upon, in part, in their Petition before the PSB, contains a so-called "scrivener's error." By motion filed in the Superior Court in September 2000, the IPPs sought summary judgement in this action. On January 19, 2001, the Washington County Superior Court dismissed the IPPs' action, which the IPPs appealed to the Vermont Supreme Court. The IPPs also asked the Vermont Supreme Court to stay the proceeding before the PSB pending the outcome of their appeal. By order dated April 5, 2001, the Vermont Supreme Court denied the IPPs' request for a stay. By Order dated April 22, 2002, the Vermont Supreme Court denied the IPP's appeal. By Motion of May 3, 2002, the IPPs have sought re-argument before the Vermont Supreme Court in this matter.

     The Company participated in various legal proceedings and regulatory filings related to the Docket throughout 2002 and 2001. In September 2001, the Petitioners and the IPPs agreed to enter into a settlement discussion and on September 28, 2001 filed a Stipulation for Stay requesting that further proceedings in the Docket be stayed to provide the parties an opportunity to engage in settlement negotiations. On October 18, 2001, the PSB Hearing Officer issued an order granting the Stipulation for Stay.

     After several extensions, on January 28, 2002, the Petitioners and the IPPs filed a Memorandum of Understanding with the PSB which, if approved, establishes a comprehensive settlement to the issues in Docket No. 6270. The Memorandum of Understanding would provide:

1.    power cost reductions nominally worth approximately $11.0 million to $14.0 million over ten years;
2.    the agreement of the IPPs to support efforts before the Vermont General Assembly and the PSB to
       authorize securitization and to negotiate for the buy-out and buy-down of the IPP contracts with the goal
       of achieving additional power cost savings; and
3.    a global resolution of various related issues.

     At this time, proceedings are continuing in PSB Docket No. 6270 to consider the Memorandum of Understanding. Technical Hearings were held before the PSB's Hearing Officer on May 1 and 2, 2002. At the hearings, certain of the non-petitioning Vermont utilities and the DPS argued that all Vermont electric utility customers should be permitted to share in the benefits arising under the Memorandum of Understanding. Subject to this and other conditions, the DPS argued that the Memorandum of Understanding should be approved. A decision is expected in 2002.

Generating Units

     The Company owns and operates 20 hydroelectric generating units, two gas turbines and one diesel peaking unit with a combined nameplate capability of 73.6 mW.

     The Company is currently in the process of relicensing or preparing to relicense eight separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 29.9 mW, or about 66.8% of the Company's total hydroelectric nameplate capacity. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. The Company is unable to predict the specific impact of the imposition of such conditions, but capital expenditures and operating costs are expected to increase in the short term to meet these licensing obligations and net generation from these projects will decrease in future periods.

     Peterson Dam: The Company has worked with environmental groups and the State of Vermont since 1998 to develop a plan to relicense Peterson Dam, a 6.2 mW hydroelectric station on the Lamoille River. The Vermont Natural Resources Council ("VNRC") has proposed removal of the dam, a 1948 hydro-generating unit that produces power to energize approximately 3,000 homes per year.

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     In August 2000, talks broke down, and the VNRC called publicly for removal of the dam. The Company has initiated broader discussions with VNRC, Trout Unlimited, the Vermont Agency of Natural Resources and other parties, related to the economic, reliability and environmental issues that Peterson's removal would create. Negotiations between the parties are continuing.

Other operation expenses The decrease of approximately $0.8 million for the first quarter of 2002 versus 2001 resulted primarily from decreased conservation and load management costs in 2002, as a result of the Vermont Energy Efficiency Utility.

Maintenance expenses The $0.7 million decrease in maintenance expense in the first quarter of 2002 compared to 2001 is primarily due to lower storm restoration costs compared to the first quarter of 2001 and lower costs associated with the Company's share of Millstone Unit #3.

Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. Income taxes increased in the first quarter of 2002 compared to 2001 due to an increase in pre-tax earnings and no material change in permanent differences for the period.

Other income and deductions Other income and deductions decreased $0.1 million for the first quarter of 2002 compared to 2001 mostly due to the Company's decision to discontinue Eversant's efforts to pursue non-regulated business opportunities.

Other interest expense The $0.1 million decrease in Other interest expense in the first quarter of 2002 compared to 2001 resulted from lower interest amortization costs in the first quarter of 2002.

Other adjustments The $0.1 million increase in Other Adjustments in the first quarter of 2002 compared to 2001 resulted from an adjustment to retained earnings related to stock option exercises.

Liquidity and Capital Resources

     The Company's liquidity is primarily affected by the level of cash generated from operations and the funding requirements of its ongoing construction programs. The Company's capital expenditure projections for the years 2002 through 2006 total approximately $ 90.3 million; these projections are revised from time-to-time to reflect changes in conditions. Net cash flow provided by operating activities generated $14.9 million and $10.1 million of cash for the three months ended March 31, 2002 and 2001, respectively.

     The Company ended the first three months of 2002 with cash and cash equivalents of $52.0 million, an increase of $6.5 million from the beginning of the year. The increase in cash for 2002 was the result of $14.9 million provided by operating activities, offset by $4.2 million used for investing activities and $4.2 million used for financing activities.

     Operating Activities Net income and depreciation, deferred income taxes and investment tax credits provided cash of $8.2 million. Approximately $6.7 million of cash was provided by working capital and other operating activities.

     Investing Activities Construction and plant expenditures used cash of approximately $3.2 million and $1.0 million was used for non-utility investments, related to Catamount's investment in Gauley River Power Partners, L.P. ("Gauley River").

     Financing Activities Dividends paid on common stock were $2.6 million, while preferred stock dividends were $0.4 million. The retirement of preferred stock required $1.0 million and the pay down of capital lease obligations required $0.3 million. The sale of common stock from the Company's Treasury shares provided $0.1 million.

Utility

     The 8.3% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum and, at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum. The Company paid the mandatory sinking fund payment in the amount of $1.0 million in the first quarter of 2002.

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     The Company has an aggregate of $16.9 million of letters of credit that support three series of Industry Development/Pollution Control Bonds. Two letters of credit totaling $11.1 million expire on August 31, 2003. The Company is in the process of extending the third letter of credit, which currently expires on August 31, 2002. These letters of credit are secured by a first mortgage lien on the same collateral supporting the Company's first mortgage bonds.

     The Company's long-term debt arrangements contain financial and non-financial covenants. At March 31, 2002, the Company was in compliance with all debt covenants related to its various debt agreements.  Substantially all Vermont utility property and plant is subject to liens under the First and Second Mortgage Bonds.

Non-Utility

     In 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility, maturing November 2006, which provides for up to $25.0 million in revolving credit loans and letters of credit, of which $21.3 million was outstanding at March 31, 2002. The interest rate is variable, prime-based. Catamount's assets secure the facility. Based on total outstanding debt of $21.5 million at March 31, 2002, the aggregate amount of Catamount's long-term debt maturities are $3.4 million, $3.2 million, $4.2 million, $5.0 million

and $5.7 million for the years 2002 through 2006, respectively. Catamount's long-term debt contains financial and non-financial covenants. At March 31, 2002, Catamount was in compliance with all covenants under the revolver except that Catamount was not in compliance with the projected minimum coverage ratio. The Lender has not declared Catamount in default since the noncompliance is due to the timing of the sale or refinancing of certain Catamount equity investments anticipated to close prior to the end of 2002. Management expects to be in compliance with the projected minimum coverage ratio following the sale or refinancing of these investments.

     In 1999, SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of Eversant, secured a $1.5 million, seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.1 million at March 31, 2002. The interest rate is fixed at 9.5% per annum. Based on outstanding debt at March 31, 2002, the aggregate amount of SEWHS's long-term debt maturities are $0.2 million, $0.2 million, $0.2 million, $0.3 million and $0.2 million for the years 2002 through 2006, respectively. SEWHS's long-term debt contains financial and non-financial covenants. At March 31, 2002, SEWHS was in compliance with all debt covenants related to its various debt agreements.

Credit Ratings

     Current credit ratings of the Company's securities by Standard & Poor's and Fitch IBCA ("Fitch") remain as follows:

	Standard & Poor's (1)	Fitch (2)
Corporate Credit Rating	BBB-	N/A
First Mortgage Bonds	BBB+	BBB
Second Mortgage Bonds	BBB-	BBB-
Preferred Stock	BB	BB+

1. Outlook: Stable
2. Outlook: Stable

     The Company cannot assure that its business will generate sufficient cash flow from operations or that future borrowing will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness, including the $75.0 million Second Mortgage Bonds, when due or to fund its other liquidity needs. The Company's ability to repay its indebtedness is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory, weather and other factors that are beyond its control. The type, timing and terms of future financing that the Company may need will be dependent upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets. The Company cannot guarantee that financing sources will be available to the Company at any given time or that the terms of such sources will be favorable.

Diversification

     Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in non-regulated business opportunities. Catamount, a subsidiary of Catamount Resources Corporation, invests through its wholly owned subsidiaries in non-regulated energy-supply generation projects in North America and Western Europe. Through its wholly owned subsidiaries, Catamount has interests in ten operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany; Mecklenburg-Vorpommern, Germany; Fort Dunlop, England; and Summersville, West Virginia.

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     In 2001, Catamount undertook a comprehensive strategic review of its operations. As a result, Catamount has refocused its efforts from being an investor in late-stage renewable energy to being primarily focused on developing, owning and operating wind energy projects. As a result of the change in strategic direction, Catamount is currently pursuing the sale of certain of its interests in non-wind electric generating assets. Depending on prices, capital and other requirements, Catamount will also entertain offers for the purchase of any of its remaining non-wind electric generating assets. Proceeds from the sales will be used to either pay down the outstanding loan balance or be reinvested in the development of new wind projects as well as the acquisition of existing wind projects. Additionally, Catamount is seeking investors and partners to co-invest with Catamount in the development, ownership and acquisition of projects, which will be financed by equity and non-recourse debt. Management cannot predict the timing or outcome of potential future asset sales or whether this new strategy will be successful.

     Catamount has projects under development in the United States and Western Europe. In June 2001, Catamount established Catamount Development GmbH, a German corporate entity, 100% owned by Catamount Heartlands Corp., a wholly owned subsidiary of Catamount. The company was formed to hold Catamount's interests in German "greenfield" development projects or projects that would be purchased by Catamount in mid- to late-stage development. In February 2002, Catamount entered into a joint venture agreement with North American Renewables Corp., a subsidiary of Group EHN-Iberdrola, named New England Windpower. The purpose of the joint venture is to develop, own and operate wind projects in New England. Additionally, in February 2002, Catamount entered into a joint development agreement with force9energy Ltd. of England to develop wind projects in England, Scotland and Wales.

     At December 31, 2001, Gauley River was classified as held-for-sale and the project interests were actively marketed for sale. In the fourth quarter, in accordance with SFAS No. 121, "Accounting for the impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121"), Catamount recorded an after-tax impairment charge to earnings of $1.4 million associated with its interests in Gauley River. The impairment was based on bids received from third parties, less estimated costs to sell. In late December 2001, Catamount issued requests for bids to several parties interested in Gauley River and, in February 2002, entered into an exclusive agreement for the sale of the project. The final $1.0 million payment pursuant to the settlement agreement with Black & Veatch Construction, Inc. for cost overruns associated with the construction of Summersville Hydroelectric Power Station, owned by Gauley River, was made on March 31, 2002.

     Although Catamount has a controlling interest in Gauley River, this investment has not been consolidated in the accompanying financial statements since it is Management's intend to sell this project and therefore control is considered temporary. For equity accounting purposes, the Gauley River investment is treated as 100% ownership.

     Catamount's Fibrothetford Limited ("Fibrothetford") equity investment has been reduced to zero as a result of losses incurred to date. As of July 1, 2001, losses were being applied to Catamount's note receivable balance. Catamount will also reserve against future interest income on the note receivable, which is expected to be approximately $1.3 million over the next twelve months. Fibrothetford received a deferment of the senior debt principal payment due September 30, 2001, avoiding a potential default. That deferred payment was made at the end of October 2001. Fibrothetford is negotiating a refinancing of its debt with a large commercial bank and its owners; Management, however, cannot predict whether Fibrothetford will ultimately be able to restructure its debt and continue as a going concern. At year end, Catamount's Fibrothetford investment was classified as held-for-sale. In the fourth quarter, in accordance with SFAS No. 121, Catamount recorded an after-tax impairment charge to earnings of $3.2 million. Also, a valuation allowance for the $2.2 million deferred tax asset was recorded. The impairment charge was based on review of expected future cash flows and expected market value of Catamount's interest given the project's current financial condition.

     In the fourth quarter 2001, Catamount recorded impairment charges for all of its interests in the Glenns Ferry and Rupert projects for a total after-tax charge of $3.0 million. The impairment charges were the result of the deteriorating financial condition of the projects' steam hosts that are essential to the projects' Qualifying Facility status and long-term viability. The steam hosts are actively seeking resolution of their current financial issues, however, Management cannot predict whether they will ultimately be successful.

     Catamount's after-tax earnings were $0.5 million and $0.4 million for the first quarter of 2002 and 2001, respectively.

     Eversant, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service-related businesses. Eversant had a 12.6% ownership interest, on a fully diluted basis, in HSS as of March 31, 2002. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via

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membership. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS launched a Commercial Services division in 2001, which meets the needs of small businesses, building owners and property managers. In May 2001, Eversant entered into a convertible loan agreement with HSS and Jupiter Capital ("Jupiter"). Under the agreement, Eversant loaned HSS $2.0 million and Jupiter loaned HSS $5.0 million, which, along with current debt balances and accrued interest, was converted to preferred securities when HSS received an additional cash investment from Jupiter in August 2001. In September 2001, Eversant recorded a $1.2 million after-tax write-down of its investment in HSS to fair market value. Eversant has previously recorded losses of $9.0 million related to its investment in HSS. At year end, Jupiter committed, based upon continued satisfactory operating progress, to provide an additional $5.0 million in funding to the business over time. The first $1.0 million was invested in December 2001 and Jupiter received options to acquire up to an aggregate of $4.0 million in preferred securities. In January, February and April 2002, Jupiter invested a total of $3.0 million and predicts that an additional $2.0-$3.0 million in funding above the $5.0 million may be required and they are currently talking to other parties about providing this capital. Eversant's fully diluted ownership position after the $5.0 million Jupiter investment would be 12.0%.

     Eversant's share of the HSS losses for 2002 was zero as the Company's equity investment was reduced to zero as a result of losses incurred to date. As of March 31, 2002, Eversant has a preferred equity investment in HSS of $1.4 million, recorded at estimated fair value.

     During 2001, AgEnergy (formerly SmartEnergy Control Systems), a wholly owned subsidiary of Eversant, filed a claim in arbitration against Westfalia-Surge, the exclusive distributor that markets and sells its SmartDrive Control product. The arbitration concerned the Company's claim that Westfalia-Surge had not conducted itself in accordance with the exclusive distributorship agreement between the parties. On January 28, 2002, the Company received an adverse decision related to the arbitration proceeding with Westfalia-Surge. The Company does not expect a material liability related to the decision and is currently in discussions with Westfalia-Surge regarding this matter.

     The Company has decided to discontinue Eversant's efforts to pursue non-regulated business opportunities.

Overall, Eversant's after-tax losses were $0.6 million and $0.2 million for the first quarter of 2002 and 2001, respectively.

Rates and Regulation

     The Company recognizes that adequate and timely rate relief is necessary if it is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted. The Company currently plans, absent any unforeseen developments, to refrain from filing any rate case related to its Vermont utility until 2006.

     See Notes 2 and 4 to the Consolidated Financial Statements for information related to Vermont Retail Rates.

Electric Industry Restructuring

     The electric utility industry is in a period of transition that may result in a shift away from ratemaking based on cost of service and return on equity to more market-based rates with energy sold to customers by competing retail energy service providers. Many states, including Vermont and New Hampshire, where the Company does business, are exploring new mechanisms to bring greater competition, customer choice and market influence to the industry while retaining the public benefits associated with the current regulatory system. Recent events, including those related to restructuring in California and uncertainties concerning the operations of the wholesale markets in New England, have resulted in a slowdown of the restructuring process in Vermont.

Vermont

     Recently, there have been three primary sources of Vermont governmental activity in attempting to restructure the electric industry in Vermont: 1) the Governor's Working Group, created by the Governor of Vermont; 2) the PSB's Docket No. 6140 through which the PSB considered proposals to restructure committed utility power supply arrangements; and 3) the PSB's Docket No. 6330, through which the PSB considered the establishment of policies and procedures to govern retail competition within the Company's service territory. At this time, the PSB has concluded its investigation into the restructuring of committed power supply arrangements in Docket No. 6140, the proceeding has been closed and the Company has actively pursued initiatives for such purposes. Additionally, in

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December 2001, the PSB issued an order closing Docket No. 6330. As a result, the Company cannot determine when or if retail competition will be introduced within the Company's Vermont service territory.

New Hampshire

     The Company is continuing to work for a negotiated settlement with parties to the New Hampshire restructuring proceedings and the NHPUC.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Competition - Risk Factors

     If retail competition is implemented in Vermont or New Hampshire, the Company is unable to predict the impact on its revenues, the Company's ability to retain existing customers with respect to their power supply purchases and attract new customers or the margins that will be realized on retail sales of electricity, if any such sales are sought. The Company expects its power distribution and transmission service to its customers to continue on an exclusive basis subject to continuing economic regulation.

     Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. SFAS No. 71 requires regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates.

     As described in Note 1 of Notes to Consolidated Financial Statements in the Company's 2001 Annual Report on Form 10-K, the Company believes it currently complies with the provisions of SFAS No. 71 for both its regulated Vermont and New Hampshire service territory and FERC-regulated wholesale businesses. In the event the Company determines that it no longer meets the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations of approximately $29.4 million on a pre-tax basis as of March 31, 2002. Criteria that give rise to the discontinuance of SFAS No. 71 include 1) increasing competition that restricts the Company's ability to establish prices to recover specific costs and 2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation.

     SFAS No. 121, adopted by the Company on January 1, 1996, requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues, be revalued based upon future cash flows. SFAS No. 121 requires that a rate-regulated enterprise recognize an impairment loss for the amount of costs excluded from recovery. As of March 31, 2002, based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's regulated businesses. Competitive influences or regulatory developments may impact this status in the future.

     Because the Company is unable to predict what form possible future restructuring legislation will take, it cannot predict if or to what extent SFAS No. 71 and 121 will continue to be applicable in the future. Also, see Note 7, Recent Accounting Pronouncements, for the new accounting standard related to impairment or disposal of long-lived assets, which replaces SFAS No. 121 effective January 1, 2002. If the Company is unable to mitigate or otherwise recover stranded costs that could arise from any potentially adverse legislation or regulation, the Company would have to assess the likelihood and magnitude of losses incurred under its power contract obligations.

     As such, the Company cannot predict whether any restructuring legislation enacted in Vermont or New Hampshire, once implemented, would have a material adverse effect on the Company's operations, financial condition or credit ratings. However, the Company's failure to recover a significant portion of its purchased power costs, would likely have a material adverse effect on the Company's results of operations, cash flows, ability to obtain capital at competitive rates and ability to exist as a going concern. It is possible that stranded cost exposure before mitigation could exceed the Company's current total common stock equity.

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PART II - OTHER INFORMATION

ITEM 1.     Legal Proceedings.

     The Company is involved in litigation in the normal course of business, which the Company does not believe will have a material adverse effect on the financial position or results of operations, except as otherwise disclosed herein.

ITEM 2.     Changes in Securities.

None.

ITEM 3.     Defaults Upon Senior Securities.

None.

ITEM 4.      Submission of Matters to a Vote of Security Holders.

(a)	The Registrant held its Annual Meeting of Stockholders on May 7, 2002.
(b)	To approve the 2002 Long-Term Incentive Plan:
			For Against Abstain Non-vote	8,968,346 1,087,681 232,165 0
(c)	Directors elected whose term will expire in year 2005:
					Votes FOR	Votes WITHHELD
		Rhonda L. Brooks Janice B. Case George MacKenzie, Jr. Herbert H. Tate Robert H. Young			10,086,355 10,050,797 10,079,506 10,073,020   9,210,268	201,837     237,395     208,686     215,172  1,077,924
	Other Directors whose terms will expire in 2003:
		Robert L. Barnett Frederic H. Bertrand Robert G. Clarke Mary Alice McKenzie
	Other Directors whose terms will expire in 2004:
		William V. Boettcher Timothy S. Cobb Luther F. Hackett Janice L. Scites

ITEM 5.     Other Information.

(a) On April 15, 2002, Jean H. Gibson was elected Senior Vice President, Chief Financial Officer, and Treasurer.

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ITEM 6.     Exhibits and Reports on Form 8-K.

(a)	List of Exhibits
	A 10.95	2000 Stock Option Plan for Key Employees (Exhibit 4.3 to Registration Statement, Registration 333-39664)
	A 10.96	Form of Deferred Compensation Plan for Officers and Directors.
	A 10.97	Management Incentive Plan for Executive Officers dated January 1, 2002.
	A 10.98	Change-In-Control Agreement dated April 15, 2002 between the Company and Jean H. Gibson.
		A - Compensation related plan, contract or arrangement
(b)	Item 5.	Other events, dated March 4, 2002 re: Settlement Agreement with Vermont Public Service Board to which the Company is a party relating to the sale of Vermont Yankee.
		Dated March 22, 2002 re: Vermont Yankee mid cycle outage and related costs to the Company.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

                                                       CENTRAL VERMONT PUBLIC SERVICE CORPORATION

                                                                                           ( Registrant)

                                            By                                               /s/ Jean H. Gibson

                                                                      Jean H. Gibson, Senior Vice President, Principal

                                                                                      Financial Officer and Treasurer

                                           By                                               /s/ John J. Holtman

                                                                      John J. Holtman, Vice President and Controller,

                                                                                     Principal Accounting Officer

Dated May 13, 2002

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